In the field of drilling in the exploration for oil and gas, an important component is that of the formulation of borehole fluids.
A completion fluid can be broadly defined as any borehole fluid placed across the producing zone prior to bring a new well in. Workover fluids are used during remedial work on an already existing well which has been in production for a period of time.
The need to control subsurface pressure can create a problem in the design of a fluid. If the formation is not too high, brines can be used, utilizing solution weight. If the formation pressures are excessive, higher density brines have been developed, or alternatively solid weighing material will have to be added to increase the density of the fluid, in both cases necessitating the use of viscosifiers and suspending agents.
The borehole fluid must be compatible with the open hole section of the wellbore. Transportation of moveable solids is important from the standpoint of cleaning out debris in the well bore, or gravel packing and normally requires the addition of viscosifiers to the fluid.
In many cases, solids suspension is required to allow working time when the fluid is static, or to leave as a packer fluid, and fluid must be able to perform all of its functions under downhole conditions of temperature and pressure.
Clear brines as completion and workover fluids has risen sharply in recent years. This increase is attributed to the minimum damaging characteristics on reservoir rocks. Specially designed polymer/brine systems use polymers as a replacement for bentonite or other clays for viscosity, weight support and fluid loss control.
Polymers used in the industry perform better at lower brine concentrations and solids have to be used as weighing materials to increase density.
As alluded to previously, a very desirable change in the formulation of a borehole fluid would be the elimination of all added particulates. One practical approach to this problem is to formulate a borehole fluid that is clear, homogeneous, dense, single phase and possesses the appropriate viscosity requirements (in general, 10 to 100 cps). Therefore, a borehole fluid containing principally a polymeric viscosifier in a high concentration brine (weighting agent) could meet the above-stated requirements. Such a borehole fluid would be quite economical since some processing steps (and materials) are eliminated. For instance, brine can be obtained directly at the drill site.
However, it should be pointed out that the ability of macromolecules to effectively viscosify a high ionic strength solution is generally poor, since the dimensions of the polymer chains tend to collapse under these conditions. This is especially true for polyelectrolytes (i.e., homogeneous-charged polymers). A collapse in the dimensions of the chain results in significant loss in viscosity. Therefore, it is imperative for successful use of polymers in high ionic strength solutions that chain expansion rather than contraction should take place.
In copending U.S. Ser. No. 562,163, filed Dec. 6, 1983, it was observed that polymeric materials composed of N-vinyl-2-pyrrolidone (NV2P), sodium styrene sulfonate (SSS) and methacrylamidopropyltrimethylammonium chloride (MAPTAC) were observed to enhance the viscosity of aqueous solutions containing high levels of salt, acid or, base. These materials meet the requirements for producing a homogeneous, single phase, high density, water-based drilling mud. The N-vinyl-2-pyrrolidone units impart a substantially improved high temperature stability to the drilling fluid.
Another method of well completion and workover is the use of acid (preferably hydrochloric acid) to dissolve or remove damage in and around the well bore. Transportation of solids is important from the standpoint of cleaning out debris from the well bore, or gravel packing. This normally requires the addition of viscosifiers to the fluid. The viscosifiers have a second function of retarding the acid reaction rate so that the acid may more evenly react with the formation and its damage.
For completion and workover fluids, the majority of the polymers being commercially used, for viscosity and suspension, are confined to hydroxy ethyl cellulose polymers (HEC) and xanthan gum (XC) which have a use temperature limit of 250.degree. F.
HEC polymers are derivatives of the cellulose polymer modified to impart water solubility, HEC will not suspend solids. Xanthan gums are high molecular weight polymers produced by bacterial, XC polymer is an excellent viscosifier and suspending agent. The HEC and especially the XC polymers, perform best in lower density brines, such as saturated sodium chloride or 10.7 to 11 lb/gal. calcium chloride brine.
For the higher density brines, a percentage of the water is tied up by the salts. This limits the ability of the polymers to yield properly. Brines up to 11.0 lb/gal. CaCl.sub.2 approaches the cost performance limit for making one of these systems. HEC will viscosify heavier brines, but the amount required increases. XC polymers become ineffective as density increases beyond 12 lb/gal.
This invention describes a process for maximizing the recovery of hydrocarbon oils from the producing reservoir of an oil or gas well by adding a sufficient quantity of N-vinyl-2-pyrrolidone-based polyampholyte terpolymers to an aqueous solution to viscosify the aqueous solution so as to form an improved thermally stable borehole fluid. The resulting polymer-modified borehole fluid displays rheological properties which are in a desirable range for thermally stable borehole fluids.
The types of N-vinyl-2-pyrrolidone-based polyampholytes that are envisioned in the present invention include N-vinyl-2-pyrrolidone as the nonionic monomer unit and the following anionic and cationic species:
Anionic: 2-acrylamido-2-methylpropane sulfonic acid, sodium styrene sulfonate, (meth)acrylic acid, 2-sulfoethylmethacrylate and the like. PA1 Cationic: Methacrylamidopropyltrimethylammonium chloride, dimethyldiallylammonium chloride, diethyldiallylammonium chloride, 2-methacryloxy-2ethyltrimethylammonium chloride, trimethylmethacryloxyethylammonium methosulfate, 2-acrylamido-2-methylpropyltrimethylammonium chloride, vinylbenzyltrimethylammonium chloride and the like.
These monomers possess the appropriate water solubility so that polymerization can take place.
The preferred species of the instant invention is low to moderate charge density N-vinyl-2-pyrrolidone based polyampholytes with approximately 70 to about 98 mole % ionic groups. A 1:1 molar ratio of anionic and cationic is not required for effective utilization of this polymer. It is found that these terpolymers are soluble (low charge density) or readily dispersible (moderate charge density) in fresh water systems. Homogeneous, clear solutions form with the addition of soluble acid, base, or salt showing that the polymer is readily soluble in these solutions. In addition, the viscosity increases with the addition of these solutes. As a consequence, these polymers are extremely effective viscosifiers in a high ionic strength, water-based borehole fluids, even at relatively low levels. Moreover, the hydrolytic stability of the N-vinyl-2-pyrrolidone moieties imparts a substantially improved high temperature stability to the water-based borehole fluid.
Aqueous solutions of the terpolymers of the instant invention can also be used as fracturing fluids.
Subterranean formations are fractured for various reasons. For example, the formation around a well may be fractured to increase the permeability. Such an increase in permeability enables fluids to be produced from the subterranean formation at a greater rate with the same pressure drop.
Fracturing a subterranean formation by applying hydraulic pressure has been demonstrated to be economical and practical. Hydraulic fracturing is improved by a fracturing liquid which has the following characteristics:
(1) The fracturing liquid is capable of holding a propping material, such as sand, in suspension while being pumped down the well and into fractures which will be formed in the formation; but it also is capable of depositing the propping material in the fractures;
(2) It has a viscosity low enough to be pumped down the well, and it allows hydraulic pressure to be generated against the formation;
(3) It flows into the fractures formed in the formation and enables extending the fractures, but affords minimal loss of the fracturing liquid into the pores of the formation;
(4) It does not plug the pores of the formation or reduce the permeability of the formation permanently.
Most fracturing liquids fail in at least one of these characteristics. Usually, the fracturing liquids have a high rate of leak-off into the formation initially and when fractures expose virgin formation surfaces. Thus, a high volumetric rate of flow or prolonged flow of the fracturing liquid is required to fracture successfully the formation.
The terpolymers of the instant invention provide a method of fracturing a subterranean formation which prevents a high rate of leak-off of the fracturing liquid into the formation.
The terpolymer of the instant invention provides a method of fracturing a subterranean formation which allows controllably thickening the fracturing liquid in situ and controllably lowering the viscosity of the fracturing liquid in situ without depending on time or temperature effects upon complex additives, or on multiple injections of different fluids.
In accordance with the invention, a subterranean formation penetrated by a well is fractured with water containing a quantity sufficient to create a shear thickening liquid composition of a water soluble terpolymer.